Method to control the physical interface between two or more fluids

ABSTRACT

A method of controlling the physical interface between two wellbore servicing fluids during the displacement of one wellbore servicing fluid by another, the method comprising selecting a liquid plug having a viscosity greater than the viscosity of the two wellbore servicing fluids, introducing a first wellbore servicing fluid into the wellbore, introducing a volume of the liquid plug into the wellbore, and introducing a second wellbore servicing fluid into the wellbore, wherein the liquid plug is selected such that the mixing between the two wellbore servicing fluids is minimized.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This disclosure relates to a method for preventing the intermixing of wellbore servicing fluids in a wellbore through the use of a liquid plug.

2. Background of the Invention

A natural resource such as oil or gas residing in a subterranean formation can be recovered by drilling a well into the formation. The subterranean formation is usually isolated from other formations using a technique known as well cementing. In particular, a wellbore is typically drilled down to the subterranean formation while circulating a drilling fluid through the wellbore. After the drilling is terminated, a string of pipe, e.g., casing, is run in the wellbore. Primary cementing is then usually performed whereby a cement slurry is pumped down through the string of pipe and into the annulus between the string of pipe and the walls of the wellbore to allow the cement slurry to set into an impermeable cement column and thereby seal the annulus. Subsequent secondary cementing operations, i.e., any cementing operation after the primary cementing operation, may also be performed. Examples of secondary cementing operations include squeeze cementing whereby a cement slurry is forced under pressure to areas of lost integrity in the annulus to seal off those areas, and the setting of temporary or permanent cement plugs in order to seal off a desired region of the wellbore.

A challenge encountered during drilling, completion, and other servicing operations is the separation of the various wellbore servicing fluids as they are pumped into the wellbore. In many instances, it is highly desirable to minimize the intermixing of these fluids at the interface. Intermingling of the fluids at the interface may inhibit the ability of a fluid to perform its intended purpose, for example, intermixing of displacement fluid with a cement slurry may lead to contamination of the cement. This contamination may cause an undesirable delay in or a failure of the setting of the cement, which can mean a significant increase in cost due to increased wait time or remedial repair of unset cement. Furthermore, the contamination may negatively affect the strength of the set cement, particularly around the shoe, where it may be desirable to have the greatest strength. In some cases, this weakening of the cement may cause a failure of the shoe test, again mandating repair. Contamination of cement may also cause undesirable acceleration of the setting of the cement. For example, a salt brine may be used as a displacement fluid which may accelerate the setting of the cement.

Separation of fluids at the interface is conventionally performed by introducing mechanical separators or volumes of liquid spacers between the fluids to be separated. In cementing operations, for example, flexible and rigid mechanical plugs, e.g. wiper plugs, are used to act as a barrier between the cement and the displacement fluid to prevent fluid intermixing at the interface as well as to wipe fluid such as drilling mud or cement off the interior wall of the casing to prevent leftover cement strings and to provide a means for detecting when the cement has been completely displaced from within the casing. Usually this detection occurs via a surge in surface pressure when the mechanical plug lands at the bottom of the casing.

Despite the prevalent use of mechanical plugs, these plugs can fail, or are incompatible with a given application. Plugs with flexible wipers can deteriorate and disintegrate under normal operating conditions and damaged plugs may not adequately prevent the intermingling of wellbore fluids and cements. There are other drawbacks associated with the use of these mechanical plugs. For example, in liner applications a drill pipe wiper dart that latches into a mechanical plug at the top of the liner is required to insure fluid separation through multiple pipe sizes. In addition these plugs may take time to drill out to continue operations and, many sizes of plugs of various types may be needed over the course of a drilling operation.

As mentioned previously, a liquid spacer may be used to separate wellbore servicing fluids. Conventionally, while these spacers/liquid flushes may separate incompatible fluids from the cement, an undesirable amount of contamination still occurs. Accordingly, an ongoing need exists for a method of minimizing the intermixing of wellbore servicing fluids during normal operations, particularly a method of minimizing the intermingling at the interface of cement with a displacement fluid.

BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS

Disclosed herein is a method of controlling the physical interface between two wellbore servicing fluids during the displacement of one wellbore servicing fluid by another, the method comprising selecting a liquid plug having a viscosity greater than the viscosity of the two wellbore servicing fluids, introducing a first wellbore servicing fluid into the wellbore, introducing a volume of the liquid plug into the wellbore, and introducing a second wellbore servicing fluid into the wellbore, wherein the liquid plug is selected such that the mixing between the two wellbore servicing fluids is minimized, for example less than about 50%.

Also disclosed herein is a method of placing a settable spacer in a wellbore in a subterranean formation comprising selecting a liquid plug composition comprising a thermally activated cement and an organophilic product and having a viscosity, wherein the viscosity of the liquid plug is chosen such that intermixing of the liquid plug with the wellbore servicing fluids ahead of and behind it is minimized, pumping a volume of the liquid plug into the wellbore, stopping circulation of the wellbore fluids when a surface pressure spike is indicated, and allowing the cement to set.

Further disclosed herein is a method of separating servicing fluids during a wellbore service operation comprising placing a liquid plug between the interface of two dissimilar wellbore servicing fluids, wherein the liquid plug is rheologically designed to minimize the mixing between the interfaces of the liquid plug and the wellbore servicing fluids.

The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter that form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a flowchart of a fluid displacement simulation, including an example of a graphical output from same.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Disclosed herein are compositions and methods to control the physical interface between two or more fluids, more specifically between two or more servicing fluids in a wellbore. In an embodiment, the method comprises placing a Liquid Plug (LP) between the two or more fluids. The use of a liquid plug, hereinafter LP, may minimize the intermixing of the LP and the fluids being separated by the LP, resulting in the separation of the two fluids while also minimizing the contamination of the separated fluids. In various embodiments, the LP may be a highly viscous material and may have various fluid properties as described herein. In some embodiments, the LP is more viscous that the two fluids that are separated by the LP. LPs such as those disclosed herein may be used to separate any two fluids, and in particular any two wellbore servicing fluids. LPs may serve additional functions as described in more detail herein. Accordingly, LPs as described herein may be used to separate non-cementitious fluids during wellbore servicing, separate cement from displacement fluid during displacement of a cement job, enhance mud displacement during cementing, provide a plug for reverse circulation cementing operations, be used as a lost circulation material and/or carrier of lost circulation material during drilling operations (i.e. pump slugs of various volumes of LP while drilling thorough lost circulation zones),provide a base for plug cementing, act as a fluid caliper, enhance formation integrity following squeeze cementing operations, and perform settable functions, such as those required during leak-off tests, the formation/placement of kick-off plugs, and plug and abandonment operations. In an embodiment, the LP is used to service a wellbore experiencing lost circulation. The viscosified LP would naturally tend to flow into the lost circulation zone. In such an embodiment, particulate bridging lost circulation material may be included in the LP and delivered directly to the lost circulation zone. Additionally, a LP may deform during use to provide separation for any number of pipe geometries thereby reducing the risk and mechanical problems associated with the multiple plug systems described previously.

In various embodiments, the LP is a composition capable of separating the interface of two fluids with minimal intermixing, as described herein, while in their intended service. For example, the LP may be a composition that is capable of separating the interface of two wellbore servicing fluids with minimal intermixing while being pumped into a wellbore. Such LP compositions may be characterized, identified, and selected based upon various fluid parameters such as density, rheology, chemical composition, and diffusion/mixing coefficients. Rheological dimensions include shear viscosity, shear rate index, yield stress, elasticity, plasticity, and shear stress history as discussed in more detail below.

A LP may be characterized by its density. The density may be measured by a pressurized fluid density balance according to the American Petroleum Institute (API) method found in API Recommended Practice 10B, Section 6. The density of a material suitable for use as an LP may be in the range of from about 0.5 g/cc to about 4.0 g/cc, alternatively from about 0.8 g/cc to about 3 g/cc, alternatively from about 1.0 g/cc to about 2.5 g/cc.

Viscosity is a measure of the resistance of a fluid to deform under shear stress. It is a measure of the resistance of a material to flow. A material with a high flow resistance displays a high viscosity. For Newtonian fluids, the shear viscosity, usually represented by μ, is independent of the shear rate. For non-Newtonian fluids, the non-Newtonian viscosity, η, is dependent on the shear rate. In an embodiment, a LP has a viscosity of from about 100 cp to about 2,000,000 cp, alternatively from about 500 to about 1,000,000 cp, alternatively from about 1200 cp to about 500,000 cp.

The shear rate is the rate of shear deformation (i.e. the rate at which adjacent layers of fluid move with respect to each other). In an embodiment, a LP has a shear rate index of from about 0.1 s⁻¹ to about 1000 s⁻¹, alternatively from about 0.5 s⁻¹ to about 200 s⁻¹, alternatively from about 1 s⁻¹ to about 100 s⁻¹.

Shear stress is the force that is required on a specific area to make a material flow at a specific shear rate. It is a stress above which the shape of a material changes without a particular volume change. A greater shear stress indicates that a larger force is required to make a material flow. The yield stress is the minimum shear stress required to make a material to plastically deform. High yield stress indicates that larger forces must be applied to the same sample area to deform the sample. The yield stress may be measured by a Brookfield YR-1 Yield Stress Rheometer. In an embodiment, a LP has a yield stress of from 40 Pascals to 40,000 Pascals, alternatively from 70 Pascals to 15,000 Pascals, alternatively from 100 Pascals to 12,000 Pascals.

A material is termed elastic if it deforms under stress, but returns to its original shape upon removal of the stress. The amount of deformation is termed the strain. For small stresses, the strain for many solids is proportional to the stress, having a constant of proportionality, termed the elasticity. The elasticity is a measure of the stiffness of the material, and is stated as the inverse of Young's modulus of elasticity. Linear elasticity, as described by Hooke's law, is an approximation, with real materials displaying some degree of non-linear behavior. Beyond the elastic limit or yield strength of an elastic material, the relationship between stress and strain breaks down and the material may irreversibly deform, exhibiting plasticity. This can be observed using stress/strain curves. In an embodiment, a LP has an elasticity of from about 0.005 psi to about 10,000 psi, alternatively from about 50 psi to about 10,000 psi, alternatively from about 500 psi to about 10,000 psi. In an embodiment, a LP has an elasticity of from about 0.005 psi to about 500 psi, alternatively from about 50 psi to about 500 psi alternatively from about 0.005 psi to about 50 psi.

As mentioned above, plasticity is a measure of a material's ability to undergo an irreversible deformation (to yield) in response to an applied shear stress. In an embodiment, a LP has a plasticity of from about 0.005 psi to about 10,000 psi, alternatively from about 50 psi to about 10,000 psi, alternatively from about 100 psi to about 10,000 psi, alternatively from about 50 psi to 100 psi, alternatively from about 0.005 psi to 50 psi.

The properties of a material may be dependent on its shear stress history, including the magnitudes and duration of the exposure of the material to shear stresses. The shear stress history may be measured by integrating the volume average shear rate (VASR) versus time history, in which the VASR is measured in units of /1 sec, while the time is in seconds. This method is described in an article by Walters et. al. entitled “Kinetic Rheology of Hydraulic Fracturing Fluids” presented at the 2001 Society of Petroleum Engineers Annual Technical Conference, presentation SPE 71660, and incorporated by reference in its entirety. In an embodiment, a LP may have a shear stress history response ranging from about 1000 to about 10 million, alternatively from about 5,000 to about 500,000.

The chemical composition of the LP may vary provided that the composition has an operable combination of the various fluid properties described herein. In various embodiments, the LP may have a chemical composition characterized by a cross-linked polymer system, a latex based solution, any mineral-based solid suspension such as bentonite clay in water, an emulsion, a naturally produced material such as tree sap, or any fluid containing a material or a combination of materials that provides the beneficial rheological properties described herein. In an embodiment, the LP may comprise a crosslinkable polymer system as described in more detail herein.

In an embodiment, a LP has structural integrity that prevents degradation of the rheological properties of the LP as it is pumped downhole.

Suitable LPs include compositions or materials having the fluid properties set forth above, which may include compositions or materials chosen from three rheological families that will be described in more detail herein below. In an embodiment, the LP is a non-linear elastic solid, a viscoelastic, a non-linear viscous fluid, or combinations thereof. Materials in these families exhibit a shear dependence of the viscosity. More specifically, rheology is the science of deformation and flow of matter. The specific relationship between a stress applied to a material and the resultant deformation of the material is a unique function of the material that defines the rheological properties of the material. These can be expressed with a rheological equation of state, which is an analytical relationship between the complete stress and the strain or strain rate tensors.

Non-Linear elastic solids are defined by the equation:

τ=G(γ)γ

where τ is the shear stress, G is the shear modulus of the material, and γ is the shear strain, or shear deformation. Unlike linear elastic (Hookean) solids, the shear modulus for non-linear elastic solids is not a constant, but rather a function of the shear deformation, γ. A LP may be a material having the simple shear deformation of a non-linear elastic solid. An example of a suitable non-linear elastic solids include for example and without limitation silicon.

Viscoelastic materials are, as the name indicates, materials having both viscous and elastic properties. Viscoelastic materials are non-Newtonian materials that may exhibit elasticity in certain conditions. A material is said to be elastic if it deforms under stress (for example, external forces), yet returns to its original shape when the stress is removed. The amount of deformation is called the strain. In response to small, rapidly-applied and then removed strain, viscoelastic fluids may deform and then return to their original shape, exhibiting elasticity. However, under larger strains, or when the strains are applied for longer times, these fluids may begin to flow, exhibiting viscous behavior. A viscoelastic material has infinite material responses depending on the strain-rate. Most polymers exhibit viscoelastic behavior, behaving more like solids at low temperatures and rapid deformation speeds. At high temperatures and slow deformation speeds, polymers are more liquid in behavior. Examples of suitable viscoelastic materials include some polymers and muddy soil.

The rheological equation of state for viscoelastic materials can be expressed as:

τ=f(γ,γ′,t . . . )

where γ is the shear strain (shear deformation), γ′ is the rate of strain (the shear rate), t is the time of subjection to strain. A LP may be a material having the simple shear deformation of a viscoelastic material.

Non-Linear viscous fluids are Non-Newtonian fluids having the rheological equation of state:

τ=η(γ′)γ′

where η is the non-Newtonian viscosity, and γ′ is the rate of strain (the shear rate). For non-linear viscous fluids, the viscosity depends on the shear rate. Pseudo-plastic fluids or “shear-thinning” fluids display an apparent viscosity decrease with the rate of shear, while shear-thickening fluids display an increase in apparent viscosity with rate of shear. A LP may be a material having the simple shear deformation of a non-linear viscous fluid. Examples of suitable non-linear viscous fluids include guar gum polymer solutions (about 0.5% w/v) crosslinked with borate, also common jello.

The fluid properties of a suitable LP may be optimized in various ways, including, but not limited to, trial and error and computational simulation. A LP can be chosen and tested for use as a liquid plug in a laboratory or in the field, and its ability to prevent intermixing at the fluid interfaces can be determined experimentally. Using trial and error, a suitable LP may be chosen for the specific fluids the LP is being used to separate and the specific wellbore conditions.

Alternatively, a LP having suitable rheological properties may be chosen through computer modeling and simulation of the well behavior during use of a LP. Referring to FIG. 1, a fluid displacement simulator 20 is shown having an input 10 and an output 30. The input 10 may include a variety of pre, post, or real-time job parameters such wellbore geometry, including the deviation, based upon experience and wellbore data such as caliper or other logging data; the casing geometry and placement schedule; the pumping schedule, including rates and volumes; the formation properties such as pressure, temperature, compressibility of the fluid to be recovered, and rock properties; and properties of the fluids to be separated and the properties of the proposed LP. Fluid properties include density, rheological dimensions, chemical composition, and diffusion/mixing coefficients as described herein.

Such input 10 may be used by fluid displacement simulator 20 to simulate the amount of mixing at an interface of the LP and another fluid, e.g., a wellbore servicing fluid such as cement. The fluid displacement simulator 20 may use analytical and/or empirical algorithms to mathematically describe multiple aspects of fluid displacement phenomena and fluid interaction, and thereby calculate the degree of intermixing of the fluids at the interfaces. The fluid displacement simulator may take into account fluid-fluid intermixing interfaces including density variations across the interface, viscosity variations across the interface, geometry (e.g. length, width, height) of the interface, and time-dependent changes occurring across the interface; casing rotating velocity and axial velocity; mimicking true Newtonian and non-Newtonian rheology; wellbore geometry and deviation; casing geometry and placement; buoyancy effects, pressure effects, temperature effects, fluid compressibility effects, rock effects; and combinations thereof.

The output 30 from the fluid displacement simulator 20 described the degree of intermixing and the extent of fluid displacement in text, graphical, or movie form. An example of a graphical output is shown by output 40 showing the interface variations 55 for density 45 and viscosity 50 of an axial slice of an annular region of two fluids (e.g., a displaced fluid and a displacing fluid) in a wellbore. Solid patterns at the top and bottom of the display represent 100% displaced fluid 60 and 100% displacing fluid 65, respectively, while non-uniformity in pattern represents intermixing at the interface. Such graphical representations, as well as other output such as numeric or percent calculations, may be used to distinguish acceptable and unacceptable amounts of intermixing. Thus, by using such software as fluid displacement simulator 20, a suitable LP for a specific wellbore servicing operation may be determined.

In various embodiments, the LP may provide for minimal intermixing at one or both interfaces between the LP and two fluids separated by the LP. For example, the LP may provide for intermixing of less than about 50% by volume of the displaced fluid anywhere mixing occurs (i.e. 50% by volume is the displacing fluid and 50% by volume is the displaced fluid). In an embodiment, the interface between an LP and a cement has intermixing of less than about 10% by volume of the displaced fluid anywhere mixing occurs (i.e. 90% by volume is the displacing fluid and 10% by volume is the displaced fluid). In another embodiment, the interface between an LP and a drilling fluid has intermixing of less than about 2% by volume of the displaced fluid anywhere mixing occurs (i.e. 98% by volume is the displacing fluid and 2% by volume is the displaced fluid).

The LP may be characterized by one or more diffusion and/or mixing coefficients. Diffusion and mixing coefficients refer to a factor of proportionality representing the amount of a material migrating across a unit area per unit time when intermingled with another material, often as a result of random or forced agitation. In an embodiment, the LP may have a diffusion coefficient of from about 1×10⁻⁸ cm²/sec to about 1×10⁻⁹ cm²/sec as determined by Fick's law of diffusion with parameters of diffusion flux (mol/cm²s), diffusion coefficient (cm²/s), concentration (mol/cm³), and position (cm). In another embodiment, the LP may have a mixing coefficient of from about 1×10⁻⁷ cm²/sec to about 1×10⁻⁸ cm²/sec as determined by Fick's law of diffusion with parameters of diffusion flux (mol/cm²s), diffusion coefficient (cm²/s), concentration (mol/cm³), and position (cm).

In an embodiment, a LP having the desirable rheological dimensions may comprise a crosslinkable polymer system and a filler. Alternatively, the LP may comprise a crosslinkable polymer system, a filler and a packing agent.

In an embodiment, the LP comprises a crosslinkable polymer system. Examples of suitable crosslinkable polymer systems include, but are not limited to, the following: a water soluble copolymer of a non-acidic ethylenically unsaturated polar monomer and a copolymerizable ethylenically unsaturated ester; a terpolymer or tetrapolymer of an ethylenically unsaturated polar monomer, an ethylenically unsaturated ester, and a monomer selected from acrylamide-2-methylpropane sulfonic acid, N-vinylpyrrolidone, or both; or combinations thereof. The copolymer may contain from one to three polar monomers and from one to three unsaturated esters. The crosslinkable polymer system may also include at least one crosslinking agent, which is herein defined as a material that is capable of crosslinking such copolymers to form a gel. As used herein, a gel is defined as a crosslinked polymer network swollen in a liquid medium. The crosslinking agent may be, for example and without limitation, an organic crosslinking agent such as a polyalkyleneimine, a polyfunctional aliphatic amine such as polyalkylenepolyamine, an aralkylamine, a heteroaralkylamine, or combinations thereof. Examples of suitable polyalkyleneimines include without limitation polymerized ethyleneimine and propyleneimine. Examples of suitable polyalkylenepolyamines include without limitation polyethylene- and polypropylene-polyamines. A description of such copolymers and crosslinking agents can be found in U.S. Pat. Nos. 5,836,392; 6,192,986, and 6,196,317, each of which is incorporated by reference herein in its entirety.

The ethylenically unsaturated esters used in the crosslinkable polymer system may be formed from a hydroxyl compound and an ethylenically unsaturated carboxylic acid selected from the group consisting of acrylic, methacrylic, crotonic, and cinnamic acids. The ethylenically unsaturated group may be in the alpha-beta or beta-gamma position relative to the carboxyl group, but it may be at a further distance. In an embodiment, the hydroxyl compound is an alcohol generally represented by the formula ROH, wherein R is an alkyl, alkenyl, cycloalkyl, aryl, arylalkyl, aromatic, or heterocyclic group that may be substituted with one or more of a hydroxyl, ether, and thioether group. The substituent can be on the same carbon atom of the R group that is bonded to the hydroxyl group in the hydroxyl compound. The hydroxyl compound may be a primary, secondary, iso, or tertiary compound. In an embodiment, a tertiary carbon atom is bonded to the hydroxyl group, e.g., t-butyl and trityl. In an embodiment, the ethylenically unsaturated ester is t-butyl acrylate.

The non-acidic ethylenically unsaturated polar monomers used in the crosslinkable polymer system can be amides, e.g., primary, secondary, and/or tertiary amides, of an unsaturated carboxylic acid. Such amides may be derived from ammonia, or a primary or secondary alkylamine, which may be optionally substituted by at least one hydroxyl group as in alkylol amides such as ethanolamides. Examples of such carboxylic derived ethylenically unsaturated polar monomers include without limitation acrylamide, methacrylamide, and acrylic ethanol amide.

In an embodiment, the crosslinkable polymer system is a copolymer of acrylamide and t-butyl acrylate, and the crosslinking agent is polyethylene imine. These materials are commercially available as the H₂ZERO service providing conformance control system from Halliburton Energy Services. The H₂ZERO service providing conformance control system is a combination of HZ-10 polymer and HZ-20 crosslinker. HZ-10 is a low molecular weight polymer consisting of polyacrylamide and an acrylate ester. The gelation rate of the H₂ZERO service providing conformance control system is controlled by the unmasking of crosslinking sites on the HZ-20 polymer which is a polyethylene imine crosslinker.

The concentrations of both HZ-10 polymer and HZ-20 crosslinker contribute to the LP reaction time, its final mechanical properties and stability. In an embodiment, the crosslinkable polymer system forms a viscous gel in from about 60 mins to about 300 mins, alternatively in from about 60 mins to about 300 mins at a temperature of from about 180° F. to about 320° F., alternatively from about 180° F. to about 225° F. and, alternatively from about 250° F. to about 320° F. The relative amounts of HZ-10 polymer and HZ-20 crosslinker suitable for use in the preparation of LPs of this disclosure will be described in detail later herein.

In an embodiment, the LP comprises a filler. Herein a filler refers to particulates, also termed finer filler material, designed to bridge off across the packing agent of the LP. Such fillers may be smaller in size than the packing agent. Details of the filler and packing agent size will be disclosed later herein. Such fillers may have a pH of from about 3 to about 10. In an embodiment, the filler has a specific gravity of less than about 1 to about 5, alternatively from about 1.5 to about 5, alternatively from about 1.75 to about 4. Without wishing to be limited by theory, fillers having a specific gravity in the disclosed range may produce a LP with greater flexibility and ductility.

Examples of suitable fillers include without limitation alkyl quaternary ammonium montmorillonite, bentonite, zeolites, barite, fly ash, calcium sulfate, and combinations thereof. In an embodiment the filler is an alkyl quarternary ammonium montmorillonite. In an embodiment, the filler is a water swellable or hydratable clay. In an alternative embodiment, the filler is an oil-based sealing composition that may comprise a hydratable polymer, an organophilic clay and a water swellable clay. Such oil-based sealing compositions are disclosed in U.S. Pat. Nos. 5,913,364; 6,167,967; 6,258,757, and 6,762,156, each of which is incorporated by reference herein in its entirety. In an embodiment, the filler material is FLEXPLUG sealant, which is a deformable, viscous, cohesive oil-based composition comprising alkyl quaternary ammonium montmorillonite commercially available from Halliburton Energy Services.

In an embodiment, the LP comprises a packing agent. Examples of packing agents include without limitation resilient materials such as graphite; fibrous materials such as cedar bark, shredded cane stalks and mineral fiber; flaky materials such as mica flakes and pieces of plastic or cellophane sheeting; and granular materials such as ground and sized limestone or marble, wood, nut hulls, formica, corncobs, gravel and cotton hulls. In an embodiment, the packing agent is a resilient graphite such as STEELSEAL or STEELSEAL FINE lost circulation additives which are dual composition graphite derivatives commercially available from Baroid Industrial Drilling Products, a Halliburton Energy Services company.

In another embodiment, the packing agent is a resin-coated particulate. Examples of suitable resin-coated particulates include without limitation resin-coated ground marble, resin-coated limestone, and resin-coated sand. In an embodiment, the packing agent is a resin-coated sand. The sand may be graded sand that is sized based on a knowledge of the size of the lost circulation zone. The graded sand may have a particle size in the range of from about 10 to about 70 mesh, U.S. Sieve Series. The graded sand can be coated with a curable resin, a tackifying agent or mixtures thereof. The hardenable resin compositions useful for coating sand and consolidating it into a hard fluid permeable mass generally comprise a hardenable organic resin and a resin-to-sand coupling agent. Such resin compositions are well known to those skilled in the art, as is their use for consolidating sand into hard fluid permeable masses. A number of such compositions are described in detail in U.S. Pat. Nos. 4,042,032, 4,070,865, 4,829,100, 5,058,676 and 5,128,390 each of which is incorporated herein by reference in its entirety. Methods and conditions for the production and use of such resin coated particulates are disclosed in U.S. Pat. Nos. 6,755,245; 6,866,099; 6,776,236; 6,742,590; 6,446,722, and 6,427,775, each of which is incorporated herein by reference in its entirety. An example of a resin suitable for coating the particulate includes without limitation SANDWEDGE NT conductivity enhancement system that is a resin coating commercially available from Halliburton Energy Services.

In some embodiments, additives may be included in the LP for improving or changing the properties thereof. Examples of such additives include but are not limited to salts, accelerants, surfactants, set retarders, defoamers, settling prevention agents, weighting materials, dispersants, vitrified shale, formation conditioning agents, particulate bridging agents, or combinations thereof. Other mechanical property modifying additives, for example, are carbon fibers, glass fibers, metal fibers, minerals fibers, and the like which can be added to further modify the mechanical properties. These additives may be included singularly or in combination. Methods for introducing these additives and their effective amounts are known to one of ordinary skill in the art.

In an embodiment, the LP includes a sufficient amount of water to form a pumpable slurry. The water may be fresh water or salt water, e.g., an unsaturated aqueous salt solution or a saturated aqueous salt solution such as brine or seawater.

In an embodiment, the LP comprises a crosslinkable polymer system and a filler. In such an embodiment, the crosslinkable polymer system may be present in an amount of from about 35% to about 90% by volume, and the filler may be present in an amount of from about 8% to about 40% by volume.

Alternatively, the LP comprises a crosslinkable polymer system, a filler and a packing agent. In such an embodiment, the crosslinkable polymer system may be present in an amount of from about 30% to about 90% by volume, the filler may be present in an amount of from about 8% to about 40% by volume, and the packing agent may be present in an amount of from about 1% to about 10% by volume.

In an embodiment a LP is prepared by combining the crosslinkable polymer system H₂ZERO service providing conformance control system with a filler, FLEXPLUG OBM sealant. In such an embodiment, the LP is prepared by combining from about 35% to about 90% by volume H₂ZERO service providing conformance control system with from about 8% to about 40% by volume FLEXPLUG OBM sealant.

The H₂ZERO service providing conformance control system is prepared by mixing the HZ-10 low molecular weight polymer consisting of polyacrylamide and an acrylate ester with the HZ-20 polyethylene imine crosslinker. The relative amounts of HZ-10 and HZ-20 to be used in the preparation of H₂ZERO can be adjusted to provide gelling within a specified time frame based on reaction conditions such as temperature and pH. For example, the amount of HZ-20 crosslinker necessary for gelling is inversely proportional to temperature wherein higher amounts of HZ-20 are required at lower temperatures to effect formation of a viscous gel. Additionally, gel time can be adjusted to compensate for the pH of the filler material. Adjustment of the H₂ZERO service providing conformance control system to provide optimum gelling as a function of temperature and/or pH is known to one of ordinary skill in the art. The filler, FLEXPLUG OBM sealant is an oil-based sealing composition comprising alkyl quaternary ammonium montmorillonite. Without wishing to be limited by theory, such oil-based sealing compositions may function by the hydratable polymer reacting with water in the well bore to immediately hydrate and form a highly viscous gel. The water swellable clay then immediately swells in the presence of water and together with the viscous gel forms a highly viscous sealing mass. The organophilic clay may then react with an oil carrier fluid to add viscosity to the composition so that the polymer and clay do not settle out of the oil prior to reacting with water in the well bore.

In another embodiment, the LP comprises a thermally activated cement and an organophilic product. In an embodiment, the LP comprises a hydraulic cement. Herein hydraulic cement refers to a powdered material that develops adhesive qualities and compressive strength when cured with water. In an embodiment, an LP comprises a metal oxide, alternatively an alkaline earth metal oxide, alternatively magnesium oxide, MgO. In an embodiment, the MgO comprises without limitation THERMATEK™ rigid setting fluid which is commercially available from Halliburton Energy Services.

In an embodiment, the LP comprises an organophilic component. In an embodiment, the organophilic component comprises an organophilic clay. Examples of suitable clays include without limitation montmorillonite, bentonite, hectorite, attapulgite, sepiolite and combinations thereof. In an embodiment, the LP comprises FLEXPLUG OBM sealant, which is a deformable, viscous, cohesive oil-based composition comprising alkyl quaternary ammonium montmorillonite commercially available from Halliburton Energy Services.

In an embodiment, the LP includes a sufficient amount of aqueous fluid to form a pumpable slurry. The aqueous fluid may be a water-based drilling mud, which may comprise fresh water or salt water, e.g., an unsaturated aqueous salt solution or a saturated aqueous salt solution such as brine or seawater.

In an embodiment, the LP comprises a thermally settable cement and an organophilic component. In such an embodiment, the thermally settable cement may be present in an amount of from about 35% to about 90% by volume, and the organophilic component may be present in an amount of from about 8% to about 40% by volume.

In an embodiment a LP is prepared by combining the rigid setting fluid THERMATEK with an organophilic component, FLEXPLUG OBM sealant. In such an embodiment, the LP is prepared by combining from about 35% to about 90% by volume THERMATEK rigid setting fluid with from about 8% to about 40% by volume FLEXPLUG OBM sealant.

The components of the LP may be combined in any order desired by the user to form a slurry that may then be placed into a wellbore for use as a liquid plug. The components of the LP may be combined using any mixing device compatible with the composition, for example a bulk mixer. In an embodiment, the components of the LP are combined at the site of the wellbore. Alternatively, the components of the LP are combined off-site and then later used at the site of the well. Methods for the preparation of a LP slurry are known to one of ordinary skill in the art.

In an embodiment, the LPs of this disclosure when placed in a wellbore act as a gellable liquid plug that is flexible, adhesive and of appreciable compressive strength. In an embodiment, the LPs of this disclosure have an appreciable static gel strength (SGS). In an embodiment, the LPs of this disclosure act as a thermally settable liquid plug.

The LPs disclosed herein may be used as a wellbore servicing fluid in a variety of wellbore servicing applications as known to one of skill in the art. As used herein, a “servicing fluid” refers to a fluid used to drill, complete, work over, fracture, repair, or in any way prepare a wellbore for the recovery of materials residing in a subterranean formation penetrated by the wellbore. Examples of servicing fluids include, but are not limited to, cement slurries, drilling fluids or muds, spacer fluids, fracturing fluids or completion fluids, all of which are well known in the art. The servicing fluid is for use in a wellbore that penetrates a subterranean formation. It is to be understood that “subterranean formation” encompasses both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.

The cementing process is one of the most important processes in the drilling and completion of a well. Cementing is done at various points within a well, at various times while drilling, and may be done within or outside the casing. Primary cementing is carried out in order to form a protective sheath around the casing and attach the casing to the wall of the well bore. This cement sheath supports the casing, prevents migration of fluids in the annulus, and protects the casing from corrosive formation fluids.

During conventional cementing operations, the sheath is formed by introducing a cement slurry into the upper end of the casing at the ground surface and allowing the cement to flow through the casing to the bottom of the well and reverse direction as it enters the annulus. The cement then flows into and through the annulus between the casing and the wall of the well bore, and circulates back to the ground surface. Circulation is then terminated and the cement is allowed to set.

Typically, a mechanical plug or plugs is used in an effort to minimize contamination of the cement slurry during placement and to indicate completion of the cementing operation. Mechanical plugs are described in U.S. Pat. Nos. 4,190,112; 4,175,619; 4,706,747; 4,756,365; 5,437,330; and 6,196,311, each of which is incorporated by reference herein in its entirety. As these mechanical plugs are subject to failure and may be incompatible with a given operation (e.g., mechanical plugs of the required size may not be available), a LP may be used in addition to or in place of mechanical plugs to enhance the physical separation of the fluids at the interface. In an embodiment, a LP is introduced into a wellbore before the addition of a cement slurry to the wellbore. In an embodiment, a LP is added to the wellbore following the pumping of cement slurry. In an embodiment, at least one LP is used in combination with at least one mechanical plug. In an embodiment, the LP contains particulate bridging materials, including, but not limited to, inert solids, hydrophobic swellable agents, and elastomers, to seal off leaks in a mechanical plug during displacement. In an embodiment, a LP introduced into the wellbore behind a cement slurry assists in the cleaning of the casing during displacement of the cement slurry, reducing or eliminating the presence of leftover strings in the casing following displacement.

During cementing, use is commonly made of collars and shoes. These are typically restrictions that are attached to the pipe string. The collar, e.g. float collar, and the shoe, e.g. float shoe, help prevent the backflow of cement during the cementing process, and often comprise a check valve to achieve this prevention of backflow. In an embodiment, a LP may provide an indication of when the cement has been displaced from the casing string at a desired depth. As the LP flows from the relatively large cross sectional area of the casing to the relatively small cross sectional area of the float shoe or collar, the pressure drop, which is a function of the viscosity of the material flowing through the restriction, would increase due to the high viscosity of the LP, yielding a surface pressure spike that may be interpreted as an end of job indicator. In an embodiment, particulates are added to the LP to increase the surface pressure indication when passing through a restriction.

In an embodiment, the LP comprises a thermally settable cement and an organophilic component. Once the LP is pumped down the string and encounters the float collar, the increased shear to get through the restriction would cause a temperature increase which would lead to cement setting. A LP of this disclosure may thus be utilized as a settable spacer. In this embodiment, over-displacement of the cement slurry would not lead to an insufficient cement job at the shoe, as the settable spacer would set as a cement upon thermal activation initiated by the increase in temperature experienced by the LP due to the increased shear during flow through a restriction.

A LP of the present disclosure may be utilized to control the physical interface between fluids during non-cementing well operations. For example, in an embodiment, a LP is used to minimize contamination of both fluids during the displacement of a drilling fluid by a completions fluid. Minimization of contamination may minimize expense incurred due to loss of valuable drilling fluids and completion brines.

Drilling fluids, cuttings and gelled fluids are often found near the formation wall of an annulus that is to be cemented. In an embodiment, a LP is run prior to the introduction of the cement slurry during primary cementing. The increased shear force of the LP as compared to the cement slurry may aid in the removal of unwanted materials from the annular wall, enhancing the success of the primary cementing operation in isolating the formation. In an embodiment, particulates are added to the LP to act as “gritty” material and aid in the drilling fluid removal.

During conventional primary cementing (i.e. flow of the slurry down the casing and back to the surface through the annulus), it is often difficult to obtain the proper circulation of cement inside the annulus due to a weak formation around the well. In addition, the hydrostatic weight of the cement exerts additional pressure on the formation, especially when increased pressure is applied to the formation to overcome the friction of the cement slurry. One technique used to overcome these difficulties, is reverse circulation cementing. Reverse circulation cementing is described in U.S. Pat. No. 6,920,929 which is incorporated by reference herein in its entirety. In reverse circulation cementing, the cement slurry is pumped down through the annulus and back up the casing. While this greatly reduces the total pressure applied to the formation, it has its own challenges. One challenge is that because no mechanical plugs can be used as are used in conventional cementing operations, the operator has no way to determine exactly when the cement completely fills the annulus, without the use of some type of expensive and time-consuming tool. The operator runs the risk of either not filling the annulus completely with the cement slurry or of running cement back up inside the casing string, covering potential productive areas and/or incurring additional time and expense to drill out this overrun cement. When reverse circulation is performed, the leading edge of the cement is in the shoe track area, necessitating additional volumes of cement be pumped back up inside the casing during reverse circulation to insure that competent cement is at the bottom of the casing. In an embodiment, a LP of the present disclosure is run ahead of the cement slurry in a reverse circulation cementing operation in order to minimize contamination of the cement at the cement/drilling fluid interface. In an embodiment, a LP of the present disclosure is introduced into the annulus ahead of the cement slurry in a reverse circulation cementing operation and gives a surface pressure indication of when the cement reaches the bottom of the casing and begins to circulate into the well by a narrowed orifice present at the bottom of the chosen casing string. In an embodiment, a LP of the present disclosure is introduced into the annulus ahead of a cement slurry in a reverse circulation cementing operation and sets up as a cement upon thermal activation.

Secondary cementing operations include cement plugging applications. It is often desired to plug portions of the wellbore for various purposes including forming a foundation for sidetracking or drilling a deviated wellbore from the original wellbore. Typically, an excess volume of cement slurry is pumped into the well to compensate for the adverse effects of contamination of the cement slurry by the drilling fluids present in the wellbore. The excess volume of slurry is to provide enough settable cement to insure a competent plug in view of the fact that a portion of the slurry that gets contaminated will be unsettable. In addition, it is often necessary to place a cement plug a considerable distance from the bottom of the well. These plugs are quite prone to failure due to drilling mud contamination when the density of the slurry exceeds that of the drilling fluid in the wellbore, since gravity increases the intermixing of the fluids, leading to a cement with inadequate compressive strength or improper positioning of the set plug. This can be the case in both vertical and deviated well applications. In an embodiment, a LP of the present disclosure, designed to prevent migration of a cement slurry, is introduced into the wellbore prior to the addition of cement slurry during formation and placement of a cement plug. In an embodiment, a LP is introduced into the wellbore ahead of and behind the cement slurry during formation of a cement plug.

Often, the exact dimensions of a drilled or cased hole are not known. For example, when a hole section has been drilled, washed out formations lead to an increased hole volume. An engineered LP of the present disclosure may be used as a fluid caliper to calculate the volume of an open hole section. In an embodiment, a LP for use as a fluid caliper may be designed to prevent intermixing of the displacing fluid and the fluid already present in the wellbore. Knowing the casing sizes and volumes, a measurement of the total fluids pumped during a circulation trip of a LP may be used to calculate the volume of an open hole section. In an embodiment, a LP is detectable upon return to the top of the well (or seabed in riserless circulation operations) by its high viscosity. In an embodiment, a LP is detectable upon returning to the surface of a well by the addition of at least one dye or marker incorporated therein.

If the primary cementing of the casing does not effectively isolate the formations, it may be necessary to perform squeeze cementing, which is the most common type of secondary (remedial) cementing. Methods of squeeze cementing are described in U.S. Pat. Nos. 5,322,124; 4,158,388; and 4,627,496, which are incorporated by reference herein in their entirety. Squeeze cementing is the process of forcing a cement slurry through holes in the casing or liner and into the annulus to plug any channels that may exist in the cement sheath. When the slurry being pumped into the wellbore encounters a permeable formation, cement solids are filtered out of the slurry as the liquid phase is forced into the formation in the form of a cement filtrate. A successful cement squeeze operation will plug the holes and cracks in the cement sheath with cement filter cake that will cure to form an impenetrable barrier. The cement is allowed to set and then a drill bit is lowered on a drill string through the casing to drill out the cement plug normally remaining in the casing. The casing may then be reperforated to continue production. A difficulty associated with squeeze cementing operations is determining when to stop pumping cement. In an embodiment, a LP is introduced into a wellbore following the cement slurry during a squeeze cement operation, and yields a surface pressure indication of when to stop. In an embodiment, a LP introduced into a wellbore behind squeeze cement seals off the permeability of the formation, enhancing the formation integrity by preventing lost circulation.

The LPs of this disclosure may provide lost circulation control in a sufficiently short time period to prevent the operator from pulling out of the hole and thus reducing nonproductive rig time. Without wishing to be limited by theory, a packing agent of the LP may immediately pack off into the lost circulation zones in the subterranean formation. The filler may then squeeze into the lost circulation zones forming a bridge between the larger sized packing agent. Finally, the thermally activated crosslinkable polymer system may gel into place to produce a permanent plug that is flexible, adhesive and of appreciable compressive strength. In addition, due to the filler within the slurry the amount of crosslinkable polymer system squeezed into the matrix of the surrounding rock may be minimized thus providing a finite layer of rock adjacent to the plug that has negligible permeability and avoids formation damage.

In many applications, it is desirable to leave a hard material in or around the casing shoe upon completion of a cementing operation. One case where this is desirable is when the driller needs to determine the pore pressure of fluid bearing formations in order to determine the maximum pressure or mud weight that may be applied to the formation during drilling operations. A leak-off test (LOT) is performed to test cement placed behind the casing and a formation integrity test (FIT) is performed to determine the pressure at which the formation will fracture or mud will be lost to the formation. Methods for performing LOT/FIT tests are given in U.S. Pat. No. 6,378,363, which is incorporated by reference herein in its entirety. During a LOT/FIT, the well is isolated from the atmosphere, and drilling mud is then pumped into the wellbore from the surface at a slow, constant volumetric flowrate, increasing the pressure in the well. The pumping continues until a predetermined test pressure is reached, or until drilling fluid loss from the well is detected. At some pressure (unless the predetermined test pressure is below the leak off pressure), fluid will enter the formation, or leak off, either moving through existing permeable paths in the formation or by fracturing the formation, thus creating space into which to flow. The formation fracture pressure is determined from the LOT/FIT results. In an embodiment, a LP comprising a thermally settable cement and an organophilic component is introduced into a well prior to drilling mud to be used for a LOT/FIT. In an embodiment, a LP sets up as a hard cement upon undergoing a temperature increase due to the restrictive nature of the float shoe, float collar, or similar restriction prior to a LOT/FIT.

In many instances, a kick-off plug is used to prepare a site for the drilling of a new well from the upper section of an existing well. In this case, often a hard cementitious material is placed in the well at the point of deviation of the new well and used to “kick off” further drilling in the desired direction. In an embodiment, in lieu of a conventional cement kick-off plug, a LP comprising a thermally settable cement and an organophilic component is introduced into a wellbore and allowed to set up as a hard kick-off plug around the shoe track.

In an embodiment, a LP may be used for plug and abandonment of a well, i.e. to prepare a well to be shut in and permanently isolated. Methods for plug and abandonment are described in U.S. Pat. Nos. 6,595,289, and 6,880,642, which are incorporated by reference herein in their entirety. Regulatory requirements mandate that strata, particularly freshwater aquifers, are adequately isolated following plug and abandonment. A series of cement plugs is set in the wellbore and tested at each stage for hydraulic isolation. In an embodiment, a highly viscous LP may be used in the placement of cement plugs. In an embodiment, a LP comprising a thermally settable cement is introduced into the wellbore and allowed to set to form strategically located plugs during plug and abandon operations.

In an embodiment, one or multiple “slugs” of LP are introduced into the drill string and pumped down to the lost circulation to seal off the lost circulation zone with little or no interruption of drilling operations and reduction in loss of drilling fluid to the lost zone. In the process of drilling a well low fracture gradients zones, fractured zones, etc. are often encountered and loss of whole drilling fluid to the formation becomes a problem. Significant losses of drilling fluid can impede the progress of drilling the well, add significant cost to the drilling of the well, prevent the drilling of the well to target depth, and/or cause the total loss of the drilled open hole section. Many lost circulation materials and systems are currently commercially available. These systems either require cessation of drilling operations to try to pump some type of treatment to seal off the lost zone or materials are incorporated into drilling fluid to try to “bridge” off the lost circulation zone. The viscous LP as disclosed herein would tend to migrate to the place where losses are occurring and may help seal off the zone due to flow resistance in small openings where losses are occurring. In an embodiment, a LP as disclosed herein when used to prevent lost circulation may comprise particulate material such as sized calcium carbonate or other particulate material. Such particulate materials have been previously described herein. The incorporation of particulate material in a LP would help deliver the needed lost circulation material directly to the lost zone without having to add it to the entire drilling fluid system.

The LPs may be introduced to the wellbore to control the intermixing of fluids. In an embodiment, the LP is placed into a wellbore as a single stream. In an embodiment, the LP is introduced into the wellbore in two streams. In an embodiment, the LP is activated by downhole conditions to form a barrier that substantially seals the wellbore. For example the LP may form a mass that plugs the zone at elevated temperatures, such as those found at higher depths within a wellbore or those occurring due to the shear required for a highly viscous fluid to pass through a restriction such as a float shoe or collar.

In other embodiments, additives are also pumped into the wellbore with LP. For example and without limitation, fluid absorbing materials, resins, aqueous superabsorbers, viscosifying agents, suspending agents, dispersing agents, or combinations thereof can be pumped in the stream with the LPs disclosed.

In an embodiment, the wellbore in which the LP is positioned belongs to a multilateral wellbore configuration. It is to be understood that a multilateral wellbore configuration includes at least two principal wellbores connected by one or more ancillary wellbores.

While preferred embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.

Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present invention. Thus, the claims are a further description and are an addition to the preferred embodiments of the present invention. The discussion of a reference herein is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural or other details supplementary to those set forth herein. 

1. A method of controlling the physical interface between two wellbore servicing fluids during the displacement of one wellbore servicing fluid by another, the method comprising: (a) selecting a liquid plug having a viscosity greater than the viscosity of the two wellbore servicing fluids; (b) introducing a first wellbore servicing fluid into the wellbore; (c) introducing a volume of the liquid plug into the wellbore; and (d) introducing a second wellbore servicing fluid into the wellbore; wherein the liquid plug is selected such that the mixing between the two wellbore servicing fluids is minimized.
 2. The method of claim 1 wherein the liquid plug is capable of being pumped as a plug of viscous material throughout the displacement.
 3. The method of claim 1 wherein the liquid plug is a thermally activated gellable material that is capable of being pumped in a plug flow condition in a deviated well.
 4. The method of claim 1 wherein the liquid plug has a diffusion coefficient of from about 1×10⁻⁸ cm²/sec to about 1×10⁻⁹ cm²/sec as determined by Fick's law of diffusion.
 5. The method of claim 1 wherein the liquid plug comprises a thermally activated cement and an organophilic product.
 6. The method of claim 5 wherein the thermally activated cement comprises magnesium oxide and the organophilic product comprises alkyl quaternary ammonium montmorillonite.
 7. The method of claim 1 wherein the liquid plug is selected from the group consisting of non-linear elastic solids, viscoelastics, non-linear viscous fluids or combinations thereof.
 8. The method of claim 1 wherein the liquid plug has a shear viscosity of from about 100 cp to about 2,000,000 cp.
 9. The method of claim 1 wherein the liquid plug has a yield stress of from about 40 Pascals to about 40,000 Pascals.
 10. The method of claim 1 wherein the liquid plug has an elasticity of from about 0.005 psi to about 10,000 psi.
 11. The method of claim 1 wherein the liquid plug has a plasticity of from about 0.005 psi to about 10,000 psi.
 12. The method of claim 1 wherein the liquid plug has a shear stress history response of from about 1000 to about 10 million.
 13. The method of claim 1 wherein the liquid plug is used as a surface pressure indicator.
 14. The method of claim 1 wherein the liquid plug comprises a crosslinkable polymer system and a filler, wherein the crosslinkable polymer system comprises a water soluble copolymer of a non-acidic ethylenically unsaturated polar monomer and a copolymerizable ethylenically unsaturated ester; a water soluble terpolymer or tetrapolymer of an ethylenically unsaturated polar monomer, an ethylenically unsaturated ester, and a monomer selected from acrylamide-2-methylpropane sulfonic acid, N-vinylpyrrolidone, or both; or combinations thereof; and a crosslinking agent comprising a polyalkyleneimine, a polyfunctional aliphatic amine, an aralkylamine, a heteroaralkylamine, or combinations thereof.
 15. The method of claim 1 wherein selecting the liquid plug comprises trial and error, computational modeling, or a combination thereof.
 16. The method of claim 15, wherein the computational modeling comprises inputting the fluid properties of the two well servicing fluids, including density, rheology, chemical composition, and diffusion coefficients; wellbore geometry, including deviation, casing geometry and placement, pumping schedule including rates and volumes; and pressure, temperature, fluid compressibility, formation properties; and calculating the degree of intermixing of the two well servicing fluids.
 17. The method of claim 14 wherein the crosslinkable polymer system comprises a copolymer of acrylamide and t-butyl acrylate and the crosslinking agent comprises polyethylene imine.
 18. The method of claim 1 wherein the liquid plug comprises a crosslinkable polymer system that is thermally activated.
 19. The method of claim 18 wherein the thermal activation occurs from about 180° F. to about 320° F.
 20. The method of claim 14 wherein the filler comprises alkyl quaternary ammonium montmorillonite, bentonite, zeolites, barite, fly ash, calcium sulfate, or combinations thereof.
 21. The method of claim 14 wherein the filler comprises a hydratable polymer, an organophilic clay, a water-swellable clay, or combinations thereof.
 22. The method of claim 14 wherein the filler comprises alkyl quaternary ammonium montmorillonite.
 23. The method of claim 1 wherein the liquid plug comprises a packing agent.
 24. The method of claim 23 wherein the packing agent is a resin coated particulate.
 25. A method of placing a settable spacer in a wellbore in a subterranean formation comprising: (a) selecting a liquid plug composition comprising a thermally activated cement and an organophilic product and having a viscosity, wherein the viscosity of the liquid plug is chosen such that intermixing of the liquid plug with the wellbore servicing fluids ahead of and behind it is minimized; (b) pumping a volume of the liquid plug into the wellbore; (c) stopping circulation of the wellbore fluids when a surface pressure spike is indicated; and (d) allowing the cement to set.
 26. A method of separating servicing fluids during a wellbore service operation comprising: placing a liquid plug between the interface of two dissimilar wellbore servicing fluids, wherein the liquid plug is rheologically designed to minimize the mixing between the interfaces of the liquid plug and the wellbore servicing fluids. 